Much of our current energy needs are met through use of hydrocarbons, such as oil, natural gas, and condensates, which are recovered from naturally occurring deposits or reservoirs. Liquid hydrocarbons are often produced by pumping them from the reservoir to storage tanks or a flow line connected to the wellhead. The pumping or "lifting" costs include capital costs, such as the pump, the prime mover (i.e., motor), the rods and the tubing, oil/water/gas separation facilities, and operating costs, such as labour, royalties, taxes, and electricity. Because some of these costs are fixed, a certain production rate is required to make such recovery economically feasible. If the revenue generated by selling the recovered hydrocarbons is less than the lifting costs to so recover them, then the well may be temporarily closed up or permanently shut in. In some cases wells may be reopened when new technology becomes available, and in other cases the well may be reopened if energy prices rise, once again making production and recovery economically attractive. Alternatively, a permanently shut-in well would be plugged with concrete and abandoned altogether.
Typically, an oil well will be shut in or abandoned when less than a third of .the original oil in place in the reservoir is recovered, because it becomes uneconomic to continue to operate the well. Thus, about two thirds of the original oil is abandoned because it cannot be economically recovered. This unrecovered oil has been recognized as a lost resource in the past and thus there have been many techniques proposed to stimulate production rates and consequently increase the ultimate recovery of oil from reservoirs.
There are a number of reasons why oil and gas well productivity may decline over time. For example, productivity declines if 1) there is insufficient pressure differential between the well and the reservoir, 2) the flow between the reservoir and the well is obstructed, or 3) the mobility of the oil is restricted due to relative permeability effects. Conventional production practice, such as waterflooding, gas re-injection and the like, is generally effective for maintaining reservoir pressure to overcome the first problem. It is normal oilfield practice to waterflood reservoirs by re-injecting the produced water along with makeup (i.e. source) water back into the reservoir.
The produced water is cleaned up prior to re-injection in order to avoid reinjection of oil back into the reservoir. Typically the residual oil concentration in the injection water, is specified to be less than 50 to 100 parts per million. However, the separation of oil from the water can experience a number of problems. For example, as a waterflood matures, the total water production increases, so larger volumes of water must be cleaned for reinjection. The separation efficiency of the treating facilities may also decrease due to the increased throughput and shorter time available for separation. The separation facilities may also experience process upsets which allow the injection water to be contaminated with oil. The net effect is that some oil is inadvertently re-injected back into the reservoir in the injection water.
The oil re-injection represents a small loss of revenue in most cases and is generally not of great concern. However, the water is usually re-injected at a temperature considerably below the reservoir temperature. At the re-injection temperature there may be considerable waxy solids present in the oil carryover. When these waxy solids are re-injected into the formation, they are very efficient at plugging the near wellbore area in the injection well. The consequences are reduced injectivity, poor pressure maintenance in the reservoir and ultimately reduced oil recovery from the reservoir.
Another problem arises if the reservoir contains several layers (zones) which are being produced simultaneously. In this case, the waxy solids will tend to preferentially plug the less permeable layers. This selective plugging occurs because the less permeable layers are more effective at filtering out the waxy solids and thereby retaining the waxy solids in the near wellbore area where they restrict inflow. The net effect is that the injection water is preferentially channelled through the most highly permeable zones (so called "thief" zones) with consequent premature waterflood breakthrough and poor sweep efficiency. Often the heterogeneous nature of a reservoir (i.e. presence of multiple layers) is difficult to recognize so a problem may not be easily diagnosed.
Several methods have been developed by the industry to stimulate injection wells to improve pressure maintenance, sweep efficiency and consequently increase profitability and extend the ultimate recovery. One common method is acidization, in which an acid is pumped into a reservoir to dissolve formation rock and precipitated scales to stimulate injection rates in wells. However, matrix acidization is not effective for wells which have solid wax damage, because the solid wax is insoluble in acid. Because acidization is inherently prone to create channels along the path of "least resistance", the acid often bypasses the low permeability wax damaged oil zone and instead penetrates directly into the high permeability undamaged zone. Thus, the acid stimulation of the injection wells tends to improve the injectivity of the high conductivity zone which contributes to premature waterflood breakthrough and poor sweep efficiency. Thus, wax deposits can limit the success of acidization stimulation, even preventing effective removal of any dissolvable rock or precipitation which are wax coated.
Another technique is referred to as hydraulic fracture. In this technique, a high pressure fluid is used to fracture the rock formation, thus creating a channel which penetrates into the reservoir. The fracture is subsequently propped open using a granular material, such as sand. The fracture bypasses hydraulic restrictions to the inflow of water into the well by creating a new open channel and also by exposing a large surface area of the reservoir rock to the channel, thereby greatly increasing injectivity of the formation surrounding the bottom of the well. However, this technique can also create channels which extend toward the production wells and consequently bypass existing oil reserves. For this reason hydraulic fracturing of injection wells is generally considered undesirable and considerable efforts are made to avoid the possibility of fracturing. If the injectivity is so low that fractures are deemed necessary, then efforts are made to keep the fractures as small as possible.
Other treatments to stimulate injection wells include perforating the casing of the well with shaped charges to provide channels or perforation tunnels through which the fluids can flow. Again this technique is fairly expensive and it can be difficult to decide exactly where the wax damaged zones are and to hit them accurately. Moreover perforating only provides a short term improvement and does not remove accumulations of wax, nor, prevent the further accumulation of wax.
Another technique for stimulating injection rates is thermal stimulation. In the case of thermal stimulation, oil, water or steam heated above grade may be pumped to the bottom of the well to try to remove wax from the recovery area. However, it has been found very difficult to transfer the heat by steam, water or oil to the bottom of the well by reason of the thermal losses which take place as the hot medium is being transported down the well bore. (Society of Petroleum Engineers, Paper No. CIM/SPE 90-57 OPTIMIZING HOT OILING/WATERING JOBS TO MINIMIZE FORMATION DAMAGE by John Nenniger and Gina Nenniger of Nenniger Engineering Inc.) Heat from the "hot oil" is lost through the casing to the rock surrounding the well. Temperature measurements at the bottom of the well show that the bottom hole temperature drops during the treatment and excessive volumes of hot fluid do not significantly raise the bottom hole temperature. Typically, the heated fluid will lose its excess temperature in the top 300-400 m section of the well due to heat losses. By the time the "hot fluid" reaches the production zone at bottom of the well, it is likely cooler than the casing and thus actually absorbs heat from the casing and the rock surrounding the well. Thus for most applications, the "hot fluid" arrives at the bottom of the well at a temperature below the reservoir temperature. Because the bottom hole temperature decreases during treatment, waxy solids are likely to precipitate from the crude oil and be filtered out in the pores of the reservoir in the recovery zone as the fluid flows into the recovery zone. Thus, although the "hot oil" technique removes the wax deposits near the wellhead, it often causes an accumulation of the waxy solids in the perforation tunnels and reservoir surrounding the well. Thus, the application of heat to the well by pumping "hot oil" into the well is inadequate to remove waxy deposits in the formation and in fact usually leads to even greater formation damage.
Another method of thermal stimulation is disclosed in Canadian Patent 1,182,392, dated Feb. 12, 1985 in the name of Richardson et al. (see also U.S. Pat. No. 4,219,083) which discloses a nitrogen gas generation system to produce a heat spike in a water-based brine solution. In this method, the salt water solution undergoes a chemical reaction to release heat, together with nitrogen gas, as it is being delivered down the well, thereby avoiding some of the heat losses associated with transporting a hot fluid down the well as discussed above for the "hot oil" technique; the salt water solution only becomes hot when it is some way down the well. The salt water solution may then be shut in for a period of about 24 hours to allow the heat carried by the solution to melt wax located in the recovery zone. The disclosure notes that wax solvents may be flushed down the well prior to or after the injection of the heat-producing salt water solution.
However, there are several inherent disadvantages to the method disclosed in U.S. Pat. No. 1,182,392. Firstly, the wax is not soluble in the salt water solution, so even if the heat developed is sufficient to melt the solid wax deposits, two separate liquid phases will occur (i.e. a liquid hydrocarbon phase including liquid wax and crude oil and a liquid aqueous phase including formation water and salt water solution). If the water saturation is high in order to get a significant temperature rise then the relative permeability of the liquid hydrocarbon phase will be very low as compared to the water and the mobility of the hydrocarbon phase containing the wax will be obstructed. Thus, the water-based fluid cannot effectively carry the melted wax back into the reservoir and thereby remove the hydraulic blockage in the near wellbore area.